- May 22, 2010
- Posted by: Art Berman
- Category: The Petroleum Truth Report
The revelation that the company used only 50 barrels of foamed cement (TudorPickeringHolt webcast) on the most critical part of the well is mind-boggling. Also, why they chose to use N2 foamed cement across a formation (that was known to contain a supercritical slush of mixed fluids whose behavior is difficult to predict) is a bit perplexing too. Perhaps it was to prevent the gas-cut cement that has been a problem on deep, high-pressure wells, but how would light, foamy cement do that?
But the 50 barrels number seems to be missing a zero, almost like it’s a typo, reminiscent of NASA’s infamous “Was that in meters or feet?” mistake that caused more than $200 million to crash into Mars. BP took foolish risks in the interest of time-saving that I cannot explain. You don’t even need your red Halliburton book to know that with 50 barrels, BP was planning to cement, at best, a short amount over the shoe of the previous casing string, just above the producing zone. This is even more perplexing given that the zone was known to have washouts. What was the thinking here?
As perplexing as the above decision-making was, BP decided not to run a Cement Bond Log (TudorPickeringHolt webcast). This might not be so bad on a straightforward infill well at modest depth and pressure, but this reservoir had already “eaten” one drill string on the first well, which had to be abandoned. There was a Schlumberger Unit and personnel on the rig. They were not utilized. I’ve run CBLs. Even a crummy, short CBL would probably have at shown bond quality and channeling (if present) and would certainly have shown the Top of Cement; in this case, with minimal cement, it would have been extremely important to know the location of the TOC.
Adding to the puzzle was the fact that there were indications that the wellbore was taking in gas. According to the log record (http://energycommerce.house.gov/Press_111/20100512/Halliburton-Last.Two.Hours.Chart.PDF) it appears that the SPP (the circulating pressure) starts to decrease at about 8 pm as part of the riser mud displacement. The displacement continues for about 45 min. From 8:00 to 8:08, the pump rate is steady, but SPP is gradually rising. Pumps are shut off for the next hour. SPP is increasing. At 9:14, pumps are started and shut off again at 9:18. SPP is significantly increasing. Pumps are re-started and from 9:20-9:30, the SPP is considerably higher than at previous flow rates. At least an hour before the blowout, the crew would have to know that they were dealing with a potentially dangerous situation. It appears that the crew may have had time to reroute the flow to the gas blow-by pipe, which can be seen on the photos, but wouldn‘t the BOP be closed, evacuation (or at least minimal personnel) on the drill floor and other necessary emergency measures be taken? Were they? The log is hard to explain. Something must have been done, but what was it, and why was it so inadequate? Was it because of the visiting top brass?
We also know that the BOP had a weak battery, causing one of its electrical modules to go down (the other one was functioning). Also, during a test, 15 feet of drill pipe was stripped through a BOP pipe ram, causing many chunks of the ram’s rubber to appear in the mud pit, and get fished out and presented to a Transocean supervisor (eyewitness, 60 Minutes interview). Yet the BOP was not pulled.
Finally, why was the riser displaced of its 14.5-lb mud BEFORE the top cement plug was installed–a reverse order operation? The answer is it made better use of the Waiting On Cement time, shortening the well-construction time. In fact, all of these bad decisions shorten the well-construction time and enhance any performance bonus that is paid. Else, they do not make basic well-construction sense in their own right.
We may never know the exact route that the gas took–it might not be very important in any case, give the appalling sequence of decisions (unless, of course, the BOPs are found to have parts from the top casing seals stuck in them). It could have come through the bottom plug, through some casing joint above that plug into the wellbore, or straight up the production casing annulus through a failed casing hanger seal assembly into the BOPs.
Oddly, MMS just made its new SCP (Sustained Casing Pressure) ruling final this month–a testament to just how ineffective MMS regulation can be. Thirty years ago, when we had about a hundred wells with SCP in the annuli, we knew we had a serious problem. So we did nothing meaningful in the way of cement or well construction, in order to save money, and over the next decade or so, the problem grew to “Houston, we have a problem” proportions of 1000 wells. Again, we rearranged the paperwork and asked MMS for more Casing Pressure Exemptions, which were usually granted. So the problem grew to 8,000 wells (a conservative MMS estimate).
Now, with the guidance and help of just two entities, BP and API, new regulations come into force that promise not to cost hardly anything, but do require new paperwork and, most importantly, require more monitoring of casing pressure annuli, and still allow a strung-out timeframe in which to act, if ever, including Casing Pressure Exemptions. The existing regs had already been weakened to allow for SCP of 20% of casing design. The new API RP90 that MMS adopted speaks only of SCF “management.“ In short, the new MMS regs ensure that there will be 12,000 wells with SCF problems, made worse as water depths and pressures increase.
One thing MMS was right about, SCP “…represent a clear hazard to the safety of personnel or the environment.” The BP well design and execution, if completed, would likely have been a future SCP problem–it just happened a lot sooner. If MMS did, as reported on some blogs, grant BP an exemption to the normal sequence of well construction on Macondo, it would not be a surprise–MMS overwhelmingly says “yes” to requests from oil companies (I don’t know the percentage, but I’ll bet it’s well over 90%. In the 50 or so MMS requests that I‘ve been privy to, all of them were granted).
According to the Wall Street Journal (http://www.rigzone.com/news/article.asp?a_id=92962), in the last 10 years, MMS enforcement cases that resulted in penalties were 66 in 2000 (a high point) to just 20 last year (it‘s lowest number). A report by the Interior Dept. Inspector General in 2000 found that MMS seldom referred safety or environmental violations to the Justice Department for criminal prosecution, even when it should have done so. Rig inspections all fell, according to agency data, to 760 in 2009, down from 1,292 in 2005. Increasingly, MMS has shifted toward a policy of industry self-regulation. The MMS in a 2005 rule change pointed to a older law that “encouraged federal agencies to ‘benefit from the expertise of the private sector’ by adopting industry standards, said the WSJ article.
All told, it seems difficult to find the common thread to the bad decisions of a minimal, foamy cement job, no CBL confirmation of placement, premature displacement of drilling mud, ignoring known problems with the BOP, and a willingness to disregard data and forge ahead, except that they all speak to hurry up and “get ’er done.” All of these were human errors, not mechanical ones. The real shame is that if even one of these decisions were made differently, this disaster probably would not have happened.